Apparatus and method for dewatering low pressure gradient gas wells

ABSTRACT

Disclosed is an apparatus and method for removing extraneous water from a natural gas well using a miniaturized jet pump assembly and a concentric coiled tubing string. The miniaturized jet pump assembly is attached to a concentric coiled tubing string at the surface and then run into the well as a single unit. Alternatively, the concentric coiled tubing string may be assembled in the well. Once downhole, the jet pump assembly is activated to remove extraneous water from the well thereby facilitating the production of natural gas. Should the functional portion of the jet pump assembly corrode or wear out, that portion may be uninstalled and replaced without removing the jet pump assembly and concentric coiled tubing string from the well.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application is a divisional application of co-pending U.S. patent application Ser. No. 11/091,250, filed Mar. 28, 2005, which is hereby incorporated by reference in its entirety. U.S. patent application Ser. No. 11/091,250 claims the benefit of priority to U.S. Provisional Application No. 60/559,647, filed Apr. 5, 2004, and U.S. Provisional Application No. 60/589,302, filed Jul. 20, 2004, which are both incorporated by reference in their entirety.

BACKGROUND OF THE INVENTION

In a typical oil or natural gas recovery process, after a well has been drilled, a tubular casing is lowered into and cemented within the wellbore. Cementing of the casing string usually includes lowering the casing to a desired depth and displacing a desired volume of cement down the inner diameter of the casing. Cement is displaced downward into the casing until it exits the bottom of the casing and moves up into the annular space between the outer diameter of the casing and the wellbore. The cement cures to firmly anchor the casing to the walls of the wellbore and seal off the well.

To access the oil or natural gas through the now sealed well casing, both the casing and concrete are perforated at a predetermined downhole location. The oil or natural gas moves from the formation into the well casing via the perforations due to the difference in pressure between the formation and the well casing interior. This pressure differential carries the oil or natural gas to the surface where it is collected.

With regard to the production of natural gas, many such wells produce small amounts of liquid along with the gas. Initially, when the pressure differential is significant, the liquid is carried to the surface with the natural gas. In addition, the well production tubulars are sized to maintain a practical flow velocity to keep the well unloaded during much of its producing life. However, as the formation pressure decreases, it becomes increasingly difficult for the gas velocity to carry the associated liquid to the surface. Accordingly, the well begins to load up with liquid, which has a negative impact on natural gas production.

Several methods have been developed to alleviate the problems associated with this liquid loading. One method involves intermittent production and unloading cycles (e.g., plunger lift), while another employs reduced sized tubulars (e.g., velocity strings) to increase gas velocity to a level sufficient to carry the liquid out of the well. Yet another method uses a capillary string to inject foamer into the well, which can improve the transport of liquid. While all are somewhat beneficial, each of these methods generally results in a lower gas production rate than if the well was allowed to produce gas without having to also carry the liquid.

Many gas wells are originally fitted, or re-completed, with relatively small production tubing in an attempt to maintain velocities sufficient to unload produced liquids. Accordingly, the introduction of any device into the production tubing capable of removing the unwanted liquid further limits the area in which natural gas can flow to the surface. The present invention minimizes this problem, removing the extraneous liquid from a natural gas well using a miniaturized jet pump assembly attached to an undersized concentric coiled tubing string.

The use of jet pumps for removing large amounts of liquid from wellbores is well known in the prior art. Briefly, jet pumps generally include a power fluid line operably coupled to the entrance of the jet pump, and a return line coupled to receive fluids from a discharge end of the pump. As the pressurized power fluid is forced, by a pump at the surface, down through the jet pump, the power fluid draws in and intermixes with the produced fluid. The power fluid and produced fluid are then returned to the surface through the return line. Down-hole jet pumps are advantageous because they have no moving parts, which increase their reliability over the more conventional mechanical pumps.

Many jet pump installations incorporate removable sub-assemblies that enable the sub-assembly to be removed remotely from the jet pump body while leaving the jet pump body intact in the well. Such jet pump sub-assemblies, also called “carriers,” can be installed for operation by pumping the “carrier” down the tubing, and may also be removed by reversing the flow of the power fluid. Hence, the “removable” jet pump may be adjusted and/or replaced without requiring that the tubing be pulled from the well.

Concentric coiled tubing or coiled-in-coiled tubing is also known in the prior art. Concentric coiled tubing strings provide two channels for fluid communication downhole, typically with one channel, such as the inner channel, used to pump fluid (liquid, gas, or multiphase fluid) downhole with a second channel, such as the annular channel formed between the concentric strings, used to return fluid to the surface. Which channel is used for which function is a matter of design choice. Both concentric coiled tubing channels could be used to pump up or down.

While both of these concepts are known in the prior art, the two have not been combined, reduced significantly in size, and employed to remove small amounts of extraneous liquid from a deep, undersized natural gas well. The rising price of natural gas has made such a system viable. Accordingly, the following invention demonstrates such.

SUMMARY OF THE INVENTION

This invention relates to a method of removing extraneous fluid from a subterranean petroleum reservoir. More particularly, this invention relates to a method of removing water from a natural gas well using a miniaturized jet pump assembly attached to an undersized concentric coiled tubing string.

In one embodiment of the present invention, a miniaturized jet pump assembly is attached to a concentric coiled tubing string at the surface and is run in the well as one unit. The jet pump assembly is typically placed below the formation perforations, in an area adjacent the extraneous water. Once correctly positioned, a power fluid is pumped down the concentric coiled tubing and used to activate the functional portion of the jet pump assembly. When activated, the jet pump assembly creates an area of low pressure that draws the extraneous water into the assembly. This extraneous water is intermixed with the power fluid and returned to the surface via the concentric coiled tubing, where it can be collected or reused.

More often than not, the functional portion of the jet pump assembly wears out with extensive use. Rather than remove the entire concentric coiled string and assembly from the well to replace the worn-out components, the functional portion can be removed from the jet pump assembly by “reversing” the power fluid flow within the concentric coiled tubing. Once the worn portion of the jet pump assembly has been replaced, the new components are pumped downhole to their appropriate location.

The dimensions of the jet pump apparatus and concentric coiled tubing string are an important part of the present invention. Many wells have relatively small production tubing at that portion of the wellbore that is producing the natural gas. Accordingly, the introduction of concentric coiled tubing into the production tubing further limits the area in which natural gas can flow to the surface. Therefore, it is desirable to utilize the smallest tubing possible. Small tubing necessarily requires a small jet pump to allow passage of the “carrier” sub-assembly through the inner coiled tubing string. As opposed to similar systems in the prior art, the present invention requires the concentric coiled tubing string to be small enough to fit inside undersized production tubing (typically with an outer diameter as small as 2⅜″ and 2⅞″), and the attached jet pump apparatus to be effectively miniaturized.

Another embodiment of the present invention is directed to an assembly and method for removing produced water essentially identical to the embodiment described above, except that a jointed tubing string is used for the outer tubing string instead of the previously referenced coiled tubing string. In this embodiment, the outer jointed tubing string may be comprised of a corrosion-resistant material. The corrosion-resistant material may extend the entire length of the outer jointed tubing string, or it may be included only in those portions of the jointed tubing string that will be adjacent to the perforations in the wellbore.

Still another embodiment of the present invention is directed to a method of installing the jet pump assembly and concentric coiled tubing string in a wellbore. This method includes running an outer coiled tubing string into a wellbore, cutting the outer tubing string and hanging it off in a “Christmas tree,” running an inner coiled tubing string (with the jet pump assembly attached) through the outer tubing string, cutting the inner tubing string, landing the jet pump assembly in a specially designed seating assembly (attached to the bottom of the previously run outer coiled tubing string), and finally hanging off the inner string in the Christmas tree on the surface. This method is particularly well suited for offshore use where lifting a spool of concentric coiled tubing is not feasible.

To ensure oil and/or natural gas cannot flow freely to the surface when a wellbore is open to the atmosphere, certain jurisdictions require one or more mechanical flow barriers to be maintained in the wellbore. The act of placing an inner coiled tubing string inside of an outer coiled tubing string and hanging it off (as referenced above) results in just such a situation where the wellbore is open to the atmosphere. Thus, when running a concentric coiled tubing string into a well it is usually necessary to include at least one mechanical barrier below the aforementioned jet pump assembly.

The permutation of a check valve, a blow out plug, an extended seal bore, a nipple profile, and a seating assembly attached to the outer coiled tubing string, together with the use of a dummy carrier set in the jet pump assembly and attached to the inner concentric coiled tubing string, provides a means of installing a concentric coiled tubing jet pump dewatering system in a natural gas well while maintaining one or more mechanical barriers during the process.

Another embodiment of the present invention is directed to a method of removing the jet pump assembly and concentric coiled tubing string from the wellbore. This method includes replacing a working carrier in the jet pump assembly with a dummy carrier, removing the inner coiled tubing string from within the outer coiled tubing string, placing a wireline plug in the lower end of the outer coiled tubing, pressure testing the wireline plug, and thereafter removing the outer coiled tubing string from the well. As with installing the concentric coiled tubing string and jet pump assembly in the wellbore, it is necessary maintain one or more mechanical barriers during the process of removing the concentric coiled tubing string and jet pump assembly. The method outlined above (and described in more detail below) accomplishes this objective.

Additional objects and advantages of the invention will become apparent as the following detailed description of the preferred embodiment is read in conjunction with the drawings. It should be noted that terminology such as “up,” “down,” “above,” “below,” and the like are used herein for convenience. These terms may not be technically accurate, as when an embodiment of the present invention is used in a horizontal wellbore. The terms “up” and “above” and the like generally refer to a direction toward the surface of a wellbore, while the terms “down” and “below” and the like generally refer to a direction away from the surface of a wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a longitudinal cross section of a jet pump assembly of the present invention.

FIG. 2 shows an alternative view of a longitudinal cross section of a jet pump assembly of the present invention.

FIG. 3 illustrates surface equipment used in a method according to one embodiment of the invention wherein the concentric coiled tubing string is assembled in the well bore. The outer coiled tubing string is illustrated being run into the existing production tubing in the well.

FIG. 4 illustrates the bottom hole assembly attached to the bottom of the outer coiled tubing string according to the method of one embodiment of the present invention.

FIG. 5 illustrates the outer coiled tubing string having been cut according to the method of one embodiment of the present invention.

FIG. 6 illustrates the installation of the slip bowl on the outer coiled tubing string according to the method of one embodiment of the present invention.

FIG. 7 illustrates the landing of the slip bowl on the outer coiled tubing string according to the method of one embodiment of the present invention.

FIG. 8 illustrates the outer coiled tubing string landed in the Christmas tree spool according to the method of one embodiment of the present invention.

FIG. 9 illustrates the jet pump assembly attached to the inner coiled tubing string according to the method of one embodiment of the present invention.

FIG. 10 illustrates the installation of the slip bowl on the inner coiled tubing string according to the method of one embodiment of the present invention.

FIG. 11 illustrates the location of the jet pump assembly during the step of removing the blow out plug from the bottom sub of the seating assembly according to the method of one embodiment of the present invention.

FIG. 12 illustrates the lowering of the inner coiled tubing string according to the method of one embodiment of the present invention.

FIG. 13 illustrates the passing of the stinger on the jet pump assembly through the flapper valve and landing of the jet pump assembly in the seating assembly according to the method of one embodiment of the present invention.

FIG. 14 illustrates a plug set in the nipple profile of the jet pump assembly according to the method of one embodiment of the present invention.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

FIGS. 1 and 2 illustrate a jet pump apparatus (1) in accordance with the present invention. In the embodiment disclosed in FIGS. 1 and 2, the jet pump apparatus (1) is comprised of an outer tubular member, referred to herein as the “shroud” (2). The shroud (2) is attached to an outer coiled tubing string (not shown) by any suitable means, but preferably by welding. Welding the shroud (2) to the outer coiled tubing string allows for a smooth connection profile between the coiled tubing and the shroud (2), thereby simplifying the surface installation and preventing any hang-ups when running the jet pump apparatus (1) into the wellbore. In an alternative embodiment, the outer tubing string (not shown) is a jointed tubing string. With a jointed tubing string, the shroud (2) may be threaded onto the lower end of the jointed tubing string.

Contained within the shroud (2) is an inner tubular member referred to as the pump housing (3). The pump housing (3) is attached to the inner coiled tubing string (not shown) by any suitable means, but preferably by means of a threaded connection. A first annulus (4) is formed between the inner surface of the shroud (2) and the outer surface of the pump housing (3). The first annulus (4) is in fluid communication with both the wellbore and any surface equipment.

Contained within the pump housing (3) is the functional portion of the jet pump apparatus (1) referred to, in total, as the carrier (5). A second annulus (6) is formed between the inner surface of the pump housing (3) and the outer surface of the carrier (5). As with the first annulus (4), the second annulus (6) is in fluid communication with both the wellbore and any surface equipment.

Moving from the top of the carrier (5) downward, the carrier (5) essentially comprises a jet nozzle (7), a throat (8), and the uppermost portion of a diffuser (9 a). Near the jet nozzle portion (7) of the carrier (5) is located a series of first sealing members (10), which in this embodiment take the form of three O-rings. These first sealing members (10) create a seal between the outer surface of the carrier (5) and the inner surface of the pump housing (3). Located near the uppermost portion of the diffuser (9 a) is a second series of sealing members (17), which in this embodiment take the form of two O-rings. These second sealing members (17) create a seal between the outer surface of the carrier (5) and the lowermost portion of the diffuser (9 b).

Below the carrier (5) is located a one-way check valve (11). The check valve (11) can be any suitable one-way-type valve, but is preferably a ball valve. The check valve (11) only allows fluid to enter the jet pump apparatus (1), rather than exit. Therefore, any fluid located within the concentric coiled tubing string is prohibited from draining out of the bottom of the tool and into the wellbore. As with the carrier (5), the check valve (11) is located inside the pump housing (3).

Below the check valve (11) is located a third series of sealing members (12), which in this embodiment again take the form of three O-rings. These sealing members (12) create a seal between the outer surface of the pump housing (3) and the inner surface of the shroud (2).

At the very bottom of the jet pump apparatus (1) is located a boot sub (13). The boot sub (13) is essentially attached to both the shroud (2) and the pump housing (3)—the attachment preferably consisting of one threaded connection and two shoulders. The dual shoulders help to maintain the positional integrity of the shroud (2) and the pump housing (3) as the inner concentric coiled tubing string attempts to expand and shift due to pressure and temperature changes. The boot sub contains a bore (14) in the lower portion thereof, which provides fluid communication between the wellbore and the inner components of the jet pump apparatus (1).

In operation, the embodiment of the jet pump apparatus (1) disclosed in FIGS. 1 and 2 is attached to concentric coiled tubing (not shown) at the surface as described above. Because the jet pump apparatus (1) is made up entirely at the surface, it can be tested and checked prior to placing the apparatus downhole. Once tested, the jet pump apparatus (1) and concentric coiled tubing string are run into the wellbore together. Typically, the complete apparatus is run in such that the jet pump apparatus (1) is placed below the perforations, at or near the location of extraneous water.

It is a well-known practice in the art to avoid running standard steel coiled tubing across natural gas perforations. Natural gas production can corrode that portion of a standard steel coiled tubing that is adjacent to the perforations. This “jet impingement” corrosion can vary based on the concentration and type of dissolved solids, formation brine, and acid gases. Accordingly, one embodiment of the present invention includes utilizing a corrosion-resistant material for the outer coiled tubing string (not shown). Typically, a corrosion resistant alloy (CRA) is used. In laboratory tests, Nitronic 30 stainless steel has proved to be corrosion resistant under simulated downhole conditions, although any suitable CRA can be used. The CRA material can extend the entire length of the outer coiled tubing string, or it may be included only in those portions of the coiled tubing that will be adjacent to the perforations (as a cost savings measure). If the CRA material is only included in a section of the outer coiled tubing string, it may be connected to the standard section by any suitable means, including welding or threaded connections.

In an alternative embodiment, a jointed tubing string (not shown) is used for the outer tubing string instead of the previously mentioned coiled tubing string. The outer jointed tubing string is made of the corrosion-resistant material referenced above. As with the coiled tubing string, the CRA material can extend the entire length of the outer jointed tubing string, or it may be included only in those portions of the jointed tubing string that will be adjacent to the perforations in the wellbore (as a cost savings measure). Nitronic 30 stainless steel has proved to be corrosion resistant when used with a jointed tubing string, although any other suitable CRA can be used. If the CRA material is only included in a section of the outer jointed tubing string, it may be connected to the standard section by any suitable means, including welding or threaded connections.

Once the jet pump apparatus (1) is lowered to the desired depth, a power fluid is pumped from the surface, down the inner coiled tubing (not shown) toward the jet pump apparatus (1). The power fluid can be any suitable substance, although produced water is preferred for cost savings. The power fluid is pumped into the pump housing (3) and eventually reaches the carrier (5). Once the power fluid reaches the carrier (5), it is initially forced through the jet nozzle (7). The power fluid exists the jet nozzle (7) at a high rate of speed and travels downward into the throat (8). From there, the power fluid moves into the uppermost portion of the diffuser (9 a) and subsequently into the lowermost portion of the diffuser (9 b). The power fluid is then forced out of the lowermost portion of the diffuser (9 b) via the diffuser opening (15). At this point, the power fluid is forced into the first annulus (4) between the inner surface of the shroud (2) and the outer surface of the pump housing (3). The power fluid is then returned to the surface via the first annulus (4) to be re-circulated or collected.

The act of pumping the power fluid from the surface down to the jet pump apparatus (1) and through the jet nozzle (7), throat (8), and diffuser portions (9 a and b), creates an area of low pressure within the pump housing (3). As noted previously, fluid communication is provided between the pump housing (3) and the wellbore via the bore (14) of the boot sub (13). Accordingly, any extraneous fluid (e.g., water) that is present in the wellbore near the boot sub (13) will be sucked into the jet pump apparatus (1) due to the area of low pressure created by the power fluid stream.

The extraneous water is sucked into the bore (14) of the boot sub (13) and past the one-way check valve (11) located at the top of the bore (14). The extraneous water then moves up the second annulus (6) until it reaches a port (16) near the jet nozzle (7) of the carrier (5). As noted earlier, the flow of the power fluid through the jet nozzle (7) creates an area of low pressure in the immediate vicinity. Accordingly, the extraneous water is sucked through the port (16) where it intermixes with the power fluid. Thereafter, the extraneous water and power fluid move through the carrier (5) and back to the surface as described previously.

The jet pump apparatus (1) of the present invention requires a relatively low amount of operational horsepower in comparison with prior art jet pump systems. As an example, ignoring friction, the removal of 20 barrels of produced water a day from an 8,000 ft. well only requires an output of approximately 1.2 horsepower from an operating jet pump assembly (1). Because the present invention is designed to remove only a relatively small amount of produced water from the wellbore, the surface equipment (not shown) operating the jet pump apparatus can be relatively small (e.g. 10 horsepower) and can function economically even though the jet pump may be operating inefficiently (e.g., at approximately 20% efficiency or less). Accordingly, the jet pump assembly (1) of the present invention is financially viable.

In a typical oilfield application, certain portions of the jet pump apparatus (1) wear out or corrode with extensive use. This wear usually occurs with regard to the carrier (5) and its sub-components. Instead of removing the entire concentric coiled tubing string and jet pump apparatus (1) from the well bore, which is time consuming and costly, the present invention allows for the removal of the worn parts without removing the entire apparatus from the wellbore.

To remove the carrier (5) from the jet pump apparatus (1), power fluid is “reverse circulated” down the first annulus (4) formed between the inner surface of the shroud (2) and the outer surface of the pump housing (3). The power fluid is prevented from exiting the jet pump apparatus (1) by the one-way check valve (11), which only allows fluid to flow into the tool, rather than out. Pressure builds up against the carrier (5) to the point where the entire assembly, including the first and second sealing members (10 and 17) are removed from the jet pump apparatus (1) and forced towards the surface. A tool trap (not shown) or similar device is then employed to retrieve the carrier (5). Once the worn carrier (5) is removed, a new carrier (5) is pumped back downhole through the inner coiled tubing (not shown) until it reaches the appropriate location in the jet pump apparatus (1).

If, for any reason, it is impossible to generate enough pressure to force the worn carrier (5) to the surface, a back up system is included on the jet pump apparatus (1). A fishing neck (18) is included on the top of the carrier (5). If the carrier (5) cannot be removed by reverse circulation, a wire-line fishing tool can be lowered into the inner coiled tubing, stabbed into the fishing neck (18), and utilized to remove the carrier mechanically.

In an alternative embodiment of the jet pump apparatus (1) disclosed in FIGS. 1 and 2, the one-way check valve (11) can be omitted from the design of the jet pump apparatus (1). Without the one-way check valve (11) in place, the power fluid will drain out of the bottom of the jet pump apparatus (1) and into the wellbore when the surface pump is switched off. This design would allow for a corrosion inhibitor to be added to the power fluid and subsequently introduced into the wellbore. Of course, without the one-way check valve (11) in place, the carrier (5) cannot be “reverse circulated” as described above. A wire-line unit (not shown) would be required to accomplish such a task.

The dimensions of the jet pump apparatus and concentric coiled tubing string are an important part of the present invention. Many wells have relatively small production tubing at that portion of the wellbore that is producing the natural gas. Accordingly, the introduction of concentric coiled tubing into the production tubing further limits the area in which natural gas can flow to the surface. Therefore, it is desirable to utilize the smallest tubing/tools possible that will remove the extraneous water and still provide sufficient flow area for natural gas production.

Assuming that production tubing has an outer diameter of 2⅞ inches, the corresponding inner diameter would only be approximately 2⅖ inches. The concentric coiled tubing and attached jet pump assembly of the present invention must be small enough to be run inside the production tubing and still leave adequate annular space to produce the natural gas. Additionally, there must be adequate annular space within the concentric coiled tubing to remove any extraneous water as described in the method above.

Therefore, as opposed to similar systems in the prior art, the present invention requires the concentric coiled tubing string to be extremely small, and the attached jet pump apparatus (1) to be effectively miniaturized. By way of example, the concentric coiled tubing may be assembled using 2″, 1¾″, or even 1½″ coiled tubing for the outer string and 1″ or ⅞″ coiled tubing for the inner string. The jet pump apparatus (1) may be approximately 1¼″ in diameter with a “carrier” in the approximate range of ⅝″ to ¾″ depending on the inner string size. Intermediate sizes of coiled tubing can be manufactured to further optimize performance if demand warrants it.

As opposed to assembling the concentric coiled tubing string at the surface (as described above), there may be circumstances that require the assembly of the concentric coiled tubing string in the wellbore. An example of this would be an offshore installation where the existing platform crane has insufficient capacity to lift the weight of a pre-assembled concentric coiled tubing reel. Therefore, another embodiment of the present invention (as described in more detail below) includes a method of running an outer coiled tubing string into a wellbore, cutting the outer tubing string and hanging it off in the “Christmas tree,” running an inner coiled tubing string (with the jet pump assembly attached) through the outer tubing string, cutting the inner tubing string, landing the jet pump assembly in a specially designed seating assembly (attached to the bottom of the previously run outer coiled tubing string), and finally hanging off the inner string in the Christmas tree on the surface.

FIG. 3 illustrates some of the surface equipment used to assemble the concentric coiled tubing string and lower it into the wellbore. Prior to lowering the outer coiled tubing (25) into the wellbore, a new spool piece (30) is installed between a master valve (35) and the remainder of the Christmas tree (34). A coiled tubing blow out preventer (“BOP”) stack (40) is installed on top of the master valve (35). The BOP stack (40) includes a plurality of hydraulically actuated rams such as shear rams, slip rams, and/or tubing or pipe rams. A hydraulically actuated work window (45) is attached between the BOP stack (40) and a lubricator (50). A stuffing box (55) is located above the lubricator and beneath an injector head (60). The devices above (e.g., injector head, stuffing box, lubricator, work window, and BOP stack) and their respective uses are well known in coiled tubing applications.

At the surface, a bottom hole assembly (“BHA”) (75) is assembled and attached to the bottom of the outer coiled tubing (25), preferably by a threaded connection. The BHA, as shown in FIG. 4, comprises a seating assembly (80), a valve body (85), and a bottom sub (90). The seating assembly (80) further comprises a landing shoulder (81), an extended seal bore (82), and a nipple profile (83). The valve body (85) is connected to the lower end of the seating assembly (80) by any suitable means such as a threaded connection. In a preferred embodiment, the valve body (85) houses a spring-biased flapper (87), which, in the closed position, will prevent the flow of well bore fluids up through the valve and into the outer coiled tubing. For those jurisdictions that require double mechanical barriers to be in place when the well is open to the atmosphere, dual flapper valves (not shown) can be utilized.

The bottom sub (90) is preferably threaded to the lowermost end of the valve body (85) and includes a profile (92) for receiving a removable blow out plug (95), which can be pre-installed in the bottom sub. While a variety of well-known blow out plugs may be used with this invention, the blow out plug disclosed in FIG. 4 includes a plurality of “dogs” that extend radially into the aforementioned profile (92). Once installed in the bottom sub (90), the blow out plug may be pressure tested while still on the surface.

After the BHA is connected to the outer coiled tubing string (25), the string is fed through the surface equipment by the injector head (60) and into existing natural gas production tubing (70), as illustrated in FIG. 3. The outer coiled tubing string (25) is lowered through the production tubing (70) until it reaches the desired depth in the wellbore. The flapper valve (87) and blow out plug (95) serve as dual mechanical barriers to fluid flow when the outer coiled tubing (25) is being run into the well.

Once the outer coiled tubing string (25) has been lowered to the desired depth, it is landed in the spool (30). This can be accomplished by closing slip rams (41) in the BOP stack to grip the outer coiled tubing (25) and closing tubing rams (42) to seal the annulus around the tubing (25), as illustrated in FIG. 5. The work window (45) is then opened and the outer coiled tubing (25) is cut by any suitable means such as a mechanical pipe cutter.

With the window (45) still open, a hang-off bushing or “slip bowl” (100) may be attached to the top of the severed tubing (25) by any suitable means. Preferably, the slip bowl (100) is bolted to the outer coiled tubing string (25) and includes one or more seals (105). The slip bowl (100) includes a profile (106) for receiving and connecting to an “overshot” (110). The overshot (110) is attached to the end of the severed outer coiled tubing (25A), as shown in FIG. 6.

The severed coiled tubing (25A) is then lowered until the overshot (110) latches onto the profile of the slip bowl (100). In the latched position, the overshot (110) can support the weight of the suspended outer coiled tubing string (25) and the BHA (75). After closing the work window (45), tubing rams (42) and slip rams (41) are opened and the outer coiled tubing (25) is lowered until the bowl (100) lands on the lowermost shoulder in the bore of the spool (30), as shown in FIG. 7. Once landed, the spool (30) supports the weight of the outer tubing string (25). Seals (105) seal against the internal bore of the spool (30). A latch (not shown) is then released from the profile (106) of the slip bowl (100) by any suitable means such as fluid pressure. FIG. 8 illustrates the outer tubing string (25) landed in the spool (30). The severed coiled tubing (25A) is then removed from the surface equipment.

Once the outer coiled tubing string (25) has been landed and the severed tubing (25A) has been removed, the master valve (35) is closed and the BOP stack (40) is changed out in preparation for running the inner string (125) of the concentric coiled tubing string. An inner string BHA (130), shown in FIG. 9, preferably comprises a jet pump assembly (135), a standing or check valve (140), a landing shoulder (145), a seal assembly (150), and a stinger (155). For added safety, a dummy carrier (not shown) may be installed in the jet pump assembly as an additional mechanical barrier.

The BHA (130) can be connected together by any suitable means such as by threaded connections between the components. Preferably, the BHA (130) is threaded to the bottom of the inner coiled tubing (125) after the inner coiled tubing (125) has been aligned with and lowered into the surface equipment. After the BHA (130) is assembled and connected to the inner coiled tubing (125), the inner coiled tubing is lowered into the outer coiled tubing (25) by the injector head (60). One of skill in the art will recognize that the injector head (60) can be adapted to handle the smaller diameter inner coiled tubing (125).

The inner coiled tubing (125) may be lowered into the outer coiled tubing (25) until the inner BHA (130) reaches the outer BHA (75). The inner coiled tubing (125) may be cut in the same manner as the outer coiled string (25). Specifically, the slip rams (41) and tubing rams (42) are closed about the inner tubing string (125). After the pressure is bled off from above the tubing rams (42), the work window (45) is opened and the tubing is cut with an appropriately sized pipe cutter.

A slip bowl (175) is connected to the top end of the suspended inner coiled tubing string (125), as shown in FIG. 10. The slip bowl (175) includes an outer diameter that will allow the bowl to land on the upper shoulder of the spool (30) and has a suitable seal assembly, such as plurality of o-ring seals, that will seal against the upper seal bore of the spool (30). An overshot (180) is attached to the lower end of the severed tubing (125A). The overshot (180) is lowered over and latched to the upwardly extending profile on the slip bowl (175). The slip rams (41) and tubing rams (42) are then opened.

The inner string (125) may then be slowly lowered until the blow out plug (95) is tagged to verify the location of the BHA (130). However, before landing the inner coiled tubing string (125) in the spool (30), the inner string is picked up a short distance to verify that the seal assembly (150) is not engaged in the seal bore (82), as shown in FIG. 11. When the lower BHA (130) is in the position shown in FIG. 11, the position of the slip bowl (175) relative to the spool (30) is illustrated in FIG. 12. Pressure may then be applied via a jet pump circulating port (32) to the annulus (151) between the inner coiled tubing (125) and the outer coiled tubing (25). The pressure opens the flapper (87) and is applied against the blow out plug (95). The pressure is increased until the plug (95) is expelled from the bottom sub (90).

The release of the plug (95) from the bottom sub will be indicated by a sudden reduction in surface pressure. As soon as the plug (95) has been released, the inner tubing string (125) is lowered and landed in the spool (30). Thus, for a moment, there will be only one mechanical barrier (i.e., the flapper (87)) downhole.

As the inner string (125) is lowered, a stinger (155) will pass through the flapper (87), holding the flapper in the open position, and will extend past the bottom sub (90) as shown in FIG. 13. However, the seal assembly (150) will encounter the seal bore (82) prior to the opening of the flapper (87), thereby providing another downhole barrier. A shoulder (145) on the inner string BHA (130) will land on the landing shoulder (81) to give a positive indication that the seal assembly (150) and the stinger (155) are properly located within the outer BHA (75). Shoulders (145) and (81) may also be used to properly space out the inner tubing string (125) prior to cutting the inner coiled tubing and installing the slip bowl (175), as is well understood in the art.

After the inner string (125) has been landed, the severed coiled tubing (125A) is removed from the surface equipment. The master valve (35) is closed and the BOP (40), work window (45), lubricator (50), stuffing box (55), and injector head (60) are nippled down and removed. If a dummy carrier has been installed in the jet pump assembly, a working carrier may be pumped down and installed after the dummy carrier has been reverse circulated out of the well.

When the jet pump assembly is activated by fluid flow pumped down the inner coiled tubing (125), water will be sucked into the stinger (155) and on to the jet pump assembly where it will be pumped out of the hole. In a preferred embodiment, a strainer serves as the stinger (155) and prevents large debris from plugging the jet pump assembly. The strainer may be a sucker rod strainer, a wire wrapped screen, a perforated/slotted pipe, or any other suitable means that has been effectively miniaturized to fit through the outer coiled tubing string (25).

In the event the concentric coiled tubing string needs to be removed from the wellbore, it is still necessary to maintain the mechanical flow barriers. In one embodiment, before pulling the inner string (125), a working carrier may be reverse circulated out of the jet pump assembly and a dummy carrier (not shown) circulated down and installed. Alternatively, a dummy carrier may be installed via wireline in the jet pump assembly. The dummy carrier will serve as a mechanical barrier for the inner string (125) as it is removed from the well. A wireline plug (175), shown in FIG. 14, may then be run into the outer coiled tubing (25) and set in a nipple profile (83). Unlike the aforementioned flapper (87), the wireline plug (175) may be tested with pressure to make sure it is holding. Once the wireline plug (175) is set and tested, the outer string (25) may then be removed from the well.

While preferred embodiments of the apparatus and methods have been discussed for purposes of this disclosure, numerous changes in the construction, installation, and function of the jet pump apparatus and concentric coiled tubing string may be made by those skilled in the art. All such changes are encompassed within the scope and spirit of the following claims. 

1. A method for lowering a concentric coiled tubing string into a wellbore, the method comprising: attaching a seating assembly to a lower end of an outer coiled tubing string; lowering the seating assembly and the outer coiled tubing string into the wellbore through a production tubing string; cutting an upper end of the outer coiled tubing string and suspending the outer coiled tubing string above the production tubing string; attaching a jet pump assembly to a lower end of an inner coiled tubing string; lowering the jet pump assembly and the inner coiled tubing string into the outer coiled tubing string until the jet pump assembly seats in the seating assembly; and cutting an upper end of the inner coiled tubing string and suspending the the inner coiled tubing string above the production tubing string.
 2. The method of claim 1, wherein the step of attaching the seating assembly to the lower end of the outer coiled tubing string further includes attaching at least one flapper valve below the seating assembly.
 3. The method of claim 2, wherein the step of attaching a seating assembly to a lower end of the outer coiled tubing string further includes attaching a blow out plug below the seating assembly and the flapper valve(s).
 4. The method of claim 1, wherein the step of attaching the seating assembly to the lower end of the outer coiled tubing string further includes providing a sealing bore with the seating assembly.
 5. The method of claim 1, wherein the step of attaching the jet pump assembly to the lower end of the inner coiled tubing string further includes attaching a strainer to the inner coiled tubing string below the jet pump assembly.
 6. The method of claim 5, wherein the step of attaching the jet pump assembly to the lower end of the inner coiled tubing string further includes attaching a sealing assembly to the inner coiled tubing string below the jet pump assembly and above the strainer.
 7. The method of claim 1, wherein the jet pump assembly acts as a mechanical barrier to fluid flow through the inner coiled tubing string.
 8. The method of claim 1, wherein the step of lowering the outer coiled tubing string and the seating assembly into the wellbore further comprises lowering the outer coiled tubing string and the seating assembly through a Christmas tree.
 9. The method of claim 1, wherein the step of lowering the inner coiled tubing string and the jet pump assembly into the wellbore further comprises lowering the inner coiled tubing string and the jet pump assembly through a Christmas tree.
 10. The method of claim 8, wherein the step of lowering the outer coiled tubing string and the seating assembly through a Christmas tree further comprising attaching a slip bowl to the upper end of the outer coiled tubing string.
 11. The method of claim 9, wherein the step of lowering the inner coiled tubing string and the seating assembly through a Christmas tree further comprising attaching a slip bowl to the upper end of the inner coiled tubing string.
 12. The method of claims 10, wherein the step of attaching a slip bowl to the upper end of the outer coiled tubing string further comprises suspending the slip bowl in a spool piece.
 13. The method of claims 11, wherein the step of attaching a slip bowl to the upper end of the inner coiled tubing string further comprises suspending the slip bowl in a spool piece.
 14. The method of claim 1, further comprising constructing the outer coiled tubing string of corrosion resistant coiled tubing.
 15. The method of claim 1, further comprising constructing that portion of the outer coiled tubing string that extends across a perforation in the wellbore of corrosion resistant coiled tubing.
 16. A method for lowering a concentric coiled tubing string into a wellbore, the method comprising: attaching a seating assembly to a lower end of an outer coiled tubing string; lowering the seating assembly and the outer coiled tubing string into the wellbore through a production tubing string; cutting an upper end of the outer coiled tubing string; suspending the outer coiled tubing string above the production tubing string using suspending means; attaching a jet pump assembly to a lower end of an inner coiled tubing string; lowering the jet pump assembly and the inner coiled tubing string into the outer coiled tubing string until the jet pump assembly seats in the seating assembly; and cutting an upper end of the inner coiled tubing string; and suspending the inner coiled tubing string above the production tubing string using the suspending means.
 17. A method for removing a concentric coiled tubing string from a wellbore, wherein the concentric coiled tubing string comprises an outer coiled tubing string positioned within a production tubing string, and an inner coiled tubing string located within the outer coiled tubing string, the method comprising: removing a portion of a jet pump assembly from the wellbore, wherein the jet pump assembly is attached to the lower end of the inner coiled tubing string; lowering a portion of a dummy jet pump assembly into the natural gas wellbore through the inner coiled tubing string; seating the dummy jet pump assembly in a seating assembly attached to the lower end of the outer coiled tubing string, wherein the jet pump dummy assembly prohibits fluid flow through the inner coiled tubing string; removing the inner coiled tubing string and the jet pump dummy assembly from the wellbore; lowering a wireline plug into the wellbore through the outer coiled tubing string; seating the wireline plug in the seating assembly attached to the lower end of the outer coiled tubing string, wherein the wireline plug prohibits fluid flow through the outer coiled tubing string toward the surface position; and removing the outer coiled tubing string and the wireline plug from the wellbore. 